1. Field of the Invention
This invention relates generally to the extraction of petroleum fluids from subsurface formations. More specifically, this invention relates to an apparatus and method for eliminating fluid build-up across the perforations within subsurface wells in order to facilitate greater extraction of petroleum fluids using the natural formation pressure as the primary driving force.
2. Description of the Prior Art
Production costs are a critical consideration in the extraction of the petroleum fluids from subsurface formations. The goal, of course, is to extract petroleum fluid from the subsurface formation at the least expense. The subsurface formation has a naturally occurring pressure that facilitates the removal of petroleum fluids to the surface. Petroleum wells that produce oil and/or gas primarily using the natural formation pressure are generally the least expensive to operate. However, the formation pressure decreases with the life of the subsurface well and thus the rate of petroleum production also declines.
In addition to the temporal decline due to production, formation pressure is adversely affected by the gradual build up of water at the bottom of the well bore. In water bearing formations, water enters the well bore through the same perforations created in the sides of the well bore which permit gaseous petroleum fluids to be extracted horizontally from the formation. As water accumulates at the bottom of the well bore, it begins to rise above and cover the perforations created in the sidewalls of the well bore. The accumulated water exerts its own hydrostatic pressure downward and through the perforation. The pressure of the accumulated water counteracts the natural formation pressure, reducing the effective driving force for producing petroleum fluids to the surface.
At some point, the hydrostatic pressure of the accumulated water overcomes the natural formation pressure such that no gaseous petroleum fluids can be naturally produced. For gas wells, the flowrate of the petroleum gas upwards to the surface must be greater than a critical fluid velocity in order to effectively remove liquids, i.e. water, located between the perforations and the surface. At or below the gas critical velocity, the gas flowrate is insufficient to produce both gas and water from the formation. In this case, the pressure due to the water covering the perforations becomes too great for the formation pressure to maintain the critical velocity of the petroleum gas. Thus, production from the gas well ceases and the well is said to have been killed by the backpressure of the accumulated water.
During the early years of oil and gas production, several basic systems were developed to counteract the effects of accumulated water in the bottom of producing wells. Chief among these systems and methods was the introduction of the tubing string. The tubing string or production casing, which runs almost the entire length of the well bore, fits within the outer bore casing to create an annulus between the two casings. The tubing string terminates towards the bottom of the well bore. One or more packers, usually located close to the lower end terminus of the tubing string, are used to seal the annulus between the outer bore casing and the inner tubing string. Thus, petroleum fluids from the formation are forced upward to the surface through the tubing string rather than through the annular space between the casings. The smaller diameter of the tubing string creates greater fluid velocities for a given formation pressure than could be achieved by the same flow upward through the annulus. This allows water to be unloaded from the production well at lower formation pressures than could have otherwise been achieved.
Tubing strings alone, however, are not adequate to drive production over the long term, because the formation pressure naturally declines over time and with continued production. For many petroleum wells in the United States, for example, the formation pressure is simply too low to effectively produce oil and/or gas. This natural reduction in formation pressure creates the same liquid loading problems within the tubing string as previously discussed; problems that will eventually kill the petroleum well. Therefore, artificial recovery methods, such as gas lift technologies, pumping technologies, etc., have been developed to actively dewater and recover petroleum fluids from subsurface wells. In artificial gas lift technologies, an injection gas is typically introduced from the surface through the annulus and into the tubing string through a one-way operating valve. The packer prevents the injection gas from flowing to the bottom of the well bore through the annulus. This prevents the injection gas from creating any additional backpressure on the formation through the perforations below the packer. As is well known in the art, the one-way operating valve is disposed at an optimum depth within the tubing string to adequately mix the injected gas with the accumulated fluids. The injection gas reduces the density of the accumulated fluids thereby allowing any remaining formation pressure to produce the accumulated fluids to the surface. Thus, the petroleum well is unloaded above the one-way operating valve using injected gas to “lift” the accumulated fluids from within the tubing string.
If the accumulated fluid rises in the tubing string to a level above the operating valve, then an increasingly high pressure may be required in order to counteract the backpressure of the fluid accumulating above the operating valve. Furthermore, the pressure required may not be readily available using equipment on the surface. To mitigate this problem, additional “unloading” valves are disposed within the tubing string at locations above the operating valve. These pressure-actuated, one-way valves are systematically opened and shut to “unload” the accumulated fluid. Starting from a position just below the level of accumulated fluid within the tubing string, an “unloading” valve is opened, while the other valves remain shut. This allows the injection gas to “lift” the volume of accumulated fluid above the opened valve in the tubing string. After this volume of accumulated fluid is removed, the valve is shut and the next lowest valve is opened. Thus, the tubing string is systematically “unloaded” by progressively opening and shutting “unloading” valves down the tubing string.
The depletion of easily accessible, near-surface petroleum reserves has resulted in petroleum wells of ever increasing depth. Gas wells, in particular, are currently constructed with long intervals requiring several tube string zones. Production problems encountered at these depths are the result of long intervals, low gas permeability, low bottom hole pressure, and the mixture of gas and water in the tubing string. For example, long intervals require a packer with a tail pipe. The tail pipe is essentially a continuation of the tubing string that extends below the packer. The tail pipe, like the tubing string, has a smaller diameter than the surrounding outer casing, therefore higher fluid velocities can be maintained in the tail pipe for the same volume of fluid. As previously described, low formation pressure effectuates a fluid velocity in the larger diameter outer casing below the packer that is insufficient to produce the liquid which accumulates at the bottom of the well bore. Any liquid carried upward toward the surface by the rising gas simply falls back and accumulates at the bottom of the well hole. The accumulated fluid increases the backpressure on the formation which subsequently reduces the gas production and in many cases eventually kills the well.
A similar situation develops if the tail pipe does not extend far enough below the packer. Without sufficient tail pipe length, the upward velocity of the fluid entering the well bore from the formation will be reduced due to the large diameter outer casing encountered at the bottom of the well bore below the packer. This reduction in velocity will be inadequate to remove liquids which accumulate at the bottom of the well bore. Any liquid carried upward toward the surface by the rising gas simply falls back and accumulates at the bottom of the well hole. The accumulating fluid increases backpressure on the formation which subsequently reduces the gas production and in many cases eventually kills the well.
The prior art continues to address the problem of liquid loading in petroleum wells by developing new and/or improved artificial methods, such as the previously disclosed gas lift technologies, which essentially replace any driving force that may be imparted by the natural formation pressure. Much of the artificial gas well liquid unloading technology, however, is energy intensive. This severely curtails the profitability of gas well production when energy costs are significant. For liquid loaded subsurface wells, the added expense of artificial recovery equipment and processes reduces the overall profitability of petroleum production and in some cases causes the wells to be marginally profitable or even unprofitable. Therefore, a more cost effective strategy for unloading petroleum wells that preferably relies on the natural formation pressure is desirable. However, with the advent of these artificial gas lift technologies, much less focus has been placed in recent years on developing systems and methods which dewater a loaded gas well using the natural formation pressure as a primary driving force.
The foregoing illustrates a few of the shortcomings of the prior art. Liquid loading at the bottom of the well bore obstructs and/or impedes the natural flow of gas through the well bore perforations. This can be especially detrimental for petroleum wells having large perforation intervals. Therefore, an economical system that systematically unloads formation liquid obstructing well bore perforations throughout the depth of well bore is highly desirable.